Online monitoring of production process using electron paramagnetic resonance(EPR)

ABSTRACT

Certain aspects of the present disclosure provide methods and apparatus for sensing a fluid flowing in a conduit using a mobile electron paramagnetic resonance (EPR) device. The mobile EPR device may include one or more EPR sensors for making EPR measurements and, for certain aspects, may include one or more other sensors for making other measurements. One example mobile EPR device for deploying in a conduit generally includes a housing configured to be conveyed by a fluid flowing in the conduit; a bore in the housing for receiving the fluid; and an EPR sensor disposed adjacent to the bore for EPR sensing of the fluid as the mobile EPR device traverses a section of the conduit.

CLAIM OF PRIORITY UNDER 35 U.S.C. §§ 119 AND 120

This application is a continuation-in-part of U.S. patent applicationSer. No. 15/891,034, entitled “Online Monitoring of Production ProcessesUsing Electron Paramagnetic Resonance (EPR)” and filed Feb. 7, 2018,which claims the benefit of U.S. Provisional Patent Application No.62/455,933, entitled “Online Monitoring of Production Process UsingElectron Paramagnetic Resonance (EPR)” and filed Feb. 7, 2017, and thebenefit of U.S. Provisional Patent Application No. 62/463,810, entitled“Online Monitoring of Production Process Using Electron ParamagneticResonance (EPR)” and filed Feb. 27, 2017, all of which are hereinincorporated by reference in their entireties.

BACKGROUND Field of the Disclosure

The present disclosure generally relates to electron paramagneticresonance (EPR) and, more specifically, to applications of EPR sensorsfor hydrocarbon recovery operations.

Relevant Background

Electron paramagnetic resonance (EPR), also referred to as electron spinresonance (ESR), is a spectroscopic and imaging technique that iscapable of providing quantitative information regarding the presence andconcentration of a variety of paramagnetic species within a sample undertest. The valence electrons of a paramagnetic species possess unpairedspin angular momentum and, thus, have net magnetic moments that tend toalign along an externally applied magnetic field. This alignment processis known as paramagnetization. EPR is a measurement technique thatrelies on the external manipulation of the direction of this electronparamagnetization, also referred to as a net electronic magnetic moment.In a typical EPR study, a polarizing static magnetic field B₀ (alsoreferred to as a DC magnetic field) is applied to a sample to align themagnetic moments of the electrons along the direction of the magneticfield B₀. Then, a high-frequency oscillating magnetic field B₁, oftenreferred to as the transverse magnetic field or the radio frequency (RF)magnetic field, is applied along a direction that is perpendicular tothe polarizing field B₀. Usually, the oscillating field B₁ is generatedusing a microwave resonator (fed via a coil or a transmission line) andis designed to excite the unpaired electrons by driving transitionsbetween the different angular momentum states of the unpairedelectron(s).

EPR technology is based on the interaction of these electron spins withthe applied RF (e.g., microwave) electromagnetic fields in the presenceof the external static (DC) magnetic field. EPR data provides valuableinformation about electronic structures and spin interactions inparamagnetic materials. EPR has found wide-ranging applications invarious science and engineering technology areas, such as studyingchemicals involving free radicals or transition metal ions.

EPR responses to oilfield fluids have been studied by many authors. Forexample, in Mamin, G. V., et al., “Toward the Asphaltene Structure byElectron Paramagnetic Resonance Relaxation Studies at High Fields (3.4T),” Energy Fuels, 2016, 30 (9), pp 6942-6946, the authors studied aseries of 12 asphaltene samples extracted from heavy oils and theoxidized bitumen of different origin using high-frequency W-band (94GHz) pulsed EPR spectroscopy. The authors effectively measured thedistance between free-radical and vanadyl components of the asphalteneand inferred mechanisms on how the vanadyl can participate inconstruction of the asphaltene aggregates via the intermolecularinteractions. Other publications on asphaltene EPR response includeBiktagirov et al., “Electron Paramagnetic Resonance Study of RotationalMobility of the Vanadyl Porphyrin Complexes in Crude Oil Asphaltenes:Probing the Effect of the Thermal Treatment of Heavy Oils,” Energy &Fuels, 2014, 28, pp 6683-6687; Tukhvatullina, A. Z, et al.,“Supramolecular Structures of Oil Systems as the Key to Regulation ofOil Behavior,” Petroleum & Environmental Biotechnology,http://dx.doi.org/10.4172/2157-7463.1000152 (2013); Crude OilEmulsions—Composition, Stability, and Characterization, Edited by ManarEI-Sayed Abdel, published by Intech, 2012, Croatia. ISBN978-953-51-0220-5; Marcela Espinosa P., et al., “Electron Spin Resonanceand Electronic Structure of Vanadyl—Porphyrin in Heavy Crude Oils,”Inorg. Chem., 2001, 40, pp. 4543-4549; Teh Fu Yen, et al.,“Investigation of the Nature of Free Radicals in Petroleum Asphaltenesand Related Substances by Electron Spin Resonance,” AnalyticalChemistry, 1962, 34(6), pp 694-700; and L. Montenari, et al.,“Asphaltene Radicals and their Interaction with Molecular Oxygen: an EPRProbe of their Molecular Characteristics and Tendency to Aggregate,”Appl. Magn. Reson., 1998, 14, pp. 81-100. All of the above papers areherein incorporated by reference in their entireties. As a generalsummary, the authors demonstrate that significant information aboutcrude oil and asphaltene can be gleaned from the EPR response. Thisinformation can be used to help mitigate asphaltene deposition within awell, which is a multibillion-dollar industry problem. All of thesepapers use laboratory reference EPR spectrometers. They do notanticipate taking EPR data in real-time using wellsite equipmentconnected to the production flow.

U.S. Pat. No. 6,573,715 to King et al., entitled “Porosity andPermeability Measurement of Underground Formations Containing Crude Oil,Using EPR Response Data” and issued Jun. 3, 2003, describes the use ofan in-well EPR apparatus. Given a correlation between volume of oil andparamagnetic response, then the in-well tool measures the EPRparamagnetic response and hence the volume of crude oil contained in therock being sensed by the tool when the tool is stationary in oneposition in the wellbore, and then it traverses the wellbore to its nextstationary position. U.S. Pat. No. 6,346,813 to Kleinberg, entitled“Magnetic Resonance Method for Characterizing Fluid Samples Withdrawnfrom Subsurface Formations” and issued Feb. 12, 2002 (hereinafter“Kleinberg '813”), considers the case of flowing pressurized fluidsamples from a wellbore into a downhole tool that is stationary in thewellbore and expelling that fluid back into the wellbore. In thisapplication, the EPR data is used to identify contaminants, such as anoil-based drilling mud versus crude oil flowing from the reservoir. Inneither of these patents do the authors disclose an option for the oilto flow freely to the surface.

More recent EPR spectrometer developments, such as those described inU.S. Pat. No. 9,689,954 to Yang et al., entitled “Integrated ElectronSpin Resonance Spectrometer” and issued Jun. 27, 2017, permit using EPRsensors in applications that were previously unachievable due to sizeconstraints. Other patents disclosing smaller devices include U.S. Pat.No. 8,212,563 to White et al., entitled “Method and Apparatus forIn-situ Measurement of Soot by Electron Spin Resonance (ESR)Spectrometry” and issued Jul. 3, 2012; U.S. Pat. No. 8,829,904 to Whiteet al., entitled “Method of and Apparatus for In-situ Measurement ofDegradation of Automotive Fluids and the Like by Micro-electron SpinResonance (ESR) Spectrometry” and issued Sep. 9, 2014; U.S. Pat. No.7,868,616 to White et al., entitled “Method of and Apparatus for In-situMeasurement of Changes in Fluid Composition by Electron Spin Resonance(ESR) Spectrometry” and issued Jan. 11, 2011; and U.S. Pat. No.5,233,303 to Bales et al., entitled “Portable Dedicated Electron SpinResonance Spectrometer” and issued Aug. 3, 1993. The entire contents ofthese five patents are herein incorporated by reference.

EPR data has been proposed to guide decision processes. For example,Kleinberg '813 proposes to use the EPR data to identify whenuncontaminated reservoir crude oil has fully displaced well fluidcontaminated by mud particles, and at that point open a valve to divertthe crude to a downhole sample chamber. U.S. Pat. No. 9,103,261 to Whiteet al., entitled “Device and Method for Adjusting Dosage of FuelAdditive Based on In-Situ Measurement of Additive and ContainmentConcentration” and issued Aug. 11, 2015, discloses a method to misciblycombine two fluids, one with contaminants, where the concentration ofthe second fluid is determined by the EPR estimation of the contaminantsin the first. These patents do not anticipate multiphase fluid flowthrough the device.

As reservoirs deplete due to oilfield extraction, the quality of a crudeoil will change. As a general statement, one can expect over time anincrease in the percentages of dissolved gas and water in the crude asit exits the reservoir. As that oil returns to the surface, the pressureseen by the oil decreases, the dissolved gas will expand, and once thepressure drops to the bubble-point, then gas will come out of solution.Above that point, the oil and gas will flow as separate phases. Duringearly production any formation water might flow with the oil, but it isvery common to see the amount of water increase over time. Enhancedrecovery operations will increase that amount of produced water yetfurther. As water (or mixes of water and gas) are injected intodedicated wells, then that water will displace oil from some porevolumes, but that same water will also start to appear in the producingwells. For wells that have been under enhanced recovery for many years(such as some Permian fields near Midland in Texas or those under waterflood in Oman), then the produced water can easily exceed 90%.

It is known that in multiphase flow, the immiscible fluids may traversein different flow regimes (e.g., bubble flow, slug flow, and emulsionflow for two liquids and bubble flow, dispersed bubble flow, plug flow,slug flow, froth flow, mist flow, churn flow, and annular flow forgas-liquid combinations). It is also known that for some of these flowregimes, turbulizers can be included in the tubular to make downstreamcross-sections of the pipe more representative of the average flow(e.g., for sampling). For slug flow, however, turbulizers are lessuseful: the first fluid will not become blended with the second. Rather,the two fluids will stay as separate components travelling along thewellbore. Such a scenario is not uncommon for applications of enhancedoil recovery when the wellhead may see many feet of water, followed by afew feet of oil/water, and then many more feet of water. Another commonscenario for heavy oil production is that the produced fluid consists ofa thick emulsion of oil with 10-30% water. It is also common that thewater will include dissolved metal ions that increase the conductivityof the water (and so decrease a measured EPR signal). In these andsimilar scenarios, it becomes challenging to take a real-timemeasurement of the EPR properties of the oil.

Applications for real-time EPR measurements of crude oil were disclosed,for example, in U.S. Patent Publication No. 2016/0223478 to Babakhani etal., entitled “EPR Systems for Flow Assurance and Logging” and filedSep. 25, 2014 (hereinafter “Babakhani '478”), which is hereinincorporated by reference in its entirety. Babakhani '478 describes thatthe EPR signal can be converted into percentages of asphaltenes, resins,waxes, and other components of crude oil. Another patent hereinincorporated by reference in its entirety is U.S. Pat. No. 8,125,224 toWhite et al., entitled “Method of and Apparatus for In-Situ Measurementof Degradation of Automotive Fluids and the Like by Micro-Electron SpinResonance (ESR) Spectrometry” and issued Feb. 28, 2012, describes thatthe ESR signal can also be combined with other measurements, such as ameasurement of viscosity, conductivity, chromatic modulation, x-rayfluorescence, infrared, and dielectric permittivity. Permittivity datais known to be useful when considering fluids with polar components,such as asphaltene particles inside crude oil. Useful methodologies canbe found, for example, in K. J. Leontaritis, “Asphaltene Deposition: AComprehensive Description of Problem Manifestations and ModelingApproaches,” SPE-18892-MS, March 1989 and Adel M. Elsharkawy, et al.,“Characterization of Asphaltenes and Resins Separated from Water-in-OilEmulsions,” Journal Petroleum Science and Technology, Volume 26,2008—Issue 2. These two papers are herein incorporated by reference intheir entireties.

Many different techniques for injecting chemicals into a well are knownin the industry. For example, U.S. Pat. No. 8,210,826 to Freeman,entitled “Controlled Liquid Injection and Blending Apparatus” and issuedJul. 3, 2012 (hereinafter “Freeman '826”), discloses one technique wherethe chemicals take the form of an additive liquid to be added to a baseliquid at a ratio driven according to a control mechanism that in turnis based on measurement of temperature, pressure, and additiveconcentration. Freeman '826 does not disclose the option of measuringthe chemical effect of that injection on a third fluid flowing from awellbore. Nonadditive injection techniques are also common in the oilindustry. In one example, the chemical mixture is blended appropriatelybefore pouring into a tank, and then a control mechanism is used tometer the rate at which that chemical is injected (e.g., to be pumpeddown a chemical injection line as described in U.S. Pat. No. 6,051,535to Bilden et al., entitled “Asphaltene Adsorption Inhibition Treatment”and issued Apr. 18, 2000).

At its simplest, the injection could take the form of a bullheading ofsolvent directly into the well, such as described in Sanjay Misra, etal., “Successful Asphaltene Cleanout Field Trial in On-Shore Abu DhabiOil Fields,” SPE 164175-MS, March 2013. In this case the controlfeedback loop is completely non-automated: it consists of waiting for afew months to see if production is at desired rate and if not thenperforming another bullhead, where the parameters to be adjusted wouldbe the chemical constituency, the amount of chemical, and the soakduration. This last non-automated feedback can be described as reactive,instead of proactive.

Accordingly, there is a need to be able to take EPR measurements at thewellsite while fluids are flowing, extract properties of that fluid, anduse that information to drive closed-loop control of a fluid managementsystem.

SUMMARY

Certain aspects of the present disclosure generally relate toapplications of electron paramagnetic resonance (EPR) sensors inhydrocarbon recovery operations.

Certain aspects of the present disclosure provide a method of sensing amultiphase fluid. The method generally includes extracting at least onecharacteristic of at least one of a first phase or a second phase in themultiphase fluid in a flowing system, performing EPR spectroscopy on atleast a portion of the multiphase fluid to generate an EPR spectrum, anddetermining at least one property of the multiphase fluid based on theEPR spectrum and the at least one characteristic.

Certain aspects of the present disclosure provide a non-transitorycomputer-readable medium storing instructions that, when executed on aprocessor, perform operations for sensing a multiphase fluid. Theoperations generally include extracting at least one characteristic ofat least one of a first phase or a second phase in the multiphase fluidin a flowing system, performing EPR spectroscopy on at least a portionof the multiphase fluid to generate an EPR spectrum, and determining atleast one property of the multiphase fluid based on the EPR spectrum andthe at least one characteristic.

Certain aspects of the present disclosure provide a system for sensing amultiphase fluid configured to flow in the system. The system generallyincludes at least one sensor configured to extract at least onecharacteristic of at least one of a first phase or a second phase in themultiphase fluid, an EPR spectrometer configured to perform EPRspectroscopy on at least a portion of the multiphase fluid to generatean EPR spectrum, and at least one processor coupled to the at least onesensor and the EPR spectrometer and configured to determine at least oneproperty of the multiphase fluid based on the EPR spectrum and the atleast one characteristic.

Certain aspects of the present disclosure provide a method of sensing afluid in a flowing system. The method generally includes performing EPRspectroscopy, using an EPR spectrometer, on at least a portion of thefluid to generate an EPR spectrum; determining at least one property ofthe fluid based on the EPR spectrum; and calculating a deviation of acurrent value of the at least one property from a baseline value of theat least one property.

Certain aspects of the present disclosure provide a non-transitorycomputer-readable medium storing instructions that, when executed on aprocessor, perform operations for sensing a fluid in a flowing system.The operations generally include performing EPR spectroscopy on at leasta portion of the fluid to generate an EPR spectrum, determining at leastone property of the fluid based on the EPR spectrum, and calculating adeviation of a current value of the at least one property from abaseline value of the at least one property.

Certain aspects of the present disclosure provide a system for sensing afluid configured to flow in the system. The system generally includes anEPR spectrometer configured to perform EPR spectroscopy on at least aportion of the fluid to generate an EPR spectrum and at least oneprocessor coupled to the EPR spectrometer. The at least one processor isconfigured to determine at least one property of the fluid based on theEPR spectrum and to calculate a deviation of a current value of the atleast one property from a baseline value of the at least one property.

Certain aspects of the present disclosure provide a method of monitoringmultiple flow systems using EPR. The method generally includesperforming EPR spectroscopy on a fluid in each of a first group of flowsystems to generate a plurality of EPR spectrums and determining, foreach of the first group of flow systems, at least one property of thefluid based on the EPR spectrum associated with the flow system.

Certain aspects of the present disclosure provide a non-transitorycomputer-readable medium storing instructions that, when executed on aprocessor, perform operations for monitoring multiple flow systems usingEPR. The operations generally include performing EPR spectroscopy on afluid in each of a first group of flow systems to generate a pluralityof EPR spectrums and determining, for each of the first group of flowsystems, at least one property of the fluid based on the EPR spectrumassociated with the flow system.

Certain aspects of the present disclosure provide a system formonitoring multiple flow systems using EPR. The system generallyincludes a plurality of EPR spectrometers and at least one processorcoupled to the plurality of EPR spectrometers. The plurality of EPRspectrometers are generally configured to perform EPR spectroscopy on afluid in each of a first group of flow systems to generate a pluralityof EPR spectrums, each EPR spectrometer being coupled to one of thefirst group of flow systems. The at least one processor is generallyconfigured to determine, for each of the first group of flow systems, atleast one property of the fluid based on the EPR spectrum associatedwith the flow system.

Certain aspects of the present disclosure provide a mobile EPR devicefor deploying in a conduit. The mobile EPR device generally includes ahousing configured to be conveyed by a fluid flowing in the conduit; abore in the housing for receiving the fluid; and an EPR sensor disposedadjacent to the bore for EPR sensing of the fluid as the mobile EPRdevice traverses a section of the conduit.

Certain aspects of the present disclosure provide a method of sensing afluid flowing in a conduit. The method generally includes traversing asection of the conduit with a mobile EPR device due to the flowing fluidand performing EPR sensing of the fluid while the mobile EPR devicetraverses the section of the conduit.

The foregoing has outlined rather broadly various features of thepresent disclosure in order that the detailed description that followsmay be better understood. Additional features and advantages of thedisclosure will be described hereinafter.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above-recited features of the presentdisclosure can be understood in detail, a more particular description,briefly summarized above, may be had by reference to aspects, some ofwhich are illustrated in the appended drawings. It is to be noted,however, that the appended drawings illustrate only certain typicalaspects of this disclosure and are therefore not to be consideredlimiting of its scope, for the description may admit to other equallyeffective aspects.

FIG. 1 is a block diagram of an electron paramagnetic resonance (EPR)spectrometer.

FIG. 2 is a block diagram of an example EPR system that can receivepressurized fluid from a wellbore, in accordance with certain aspects ofthe present disclosure.

FIG. 3 is a block diagram of an example EPR system in which somecomponents are positioned near the wellbore, whereas other componentsare located remote from the wellbore, in accordance with certain aspectsof the present disclosure.

FIG. 4 is a block diagram of an example EPR system with a separator anda pump to increase the sensitivity of an EPR spectrometer to aparticular component of a multiphase fluid from a wellbore, inaccordance with certain aspects of the present disclosure.

FIG. 5 is a flow diagram of example operations for controlling a systembased on EPR sensing, in accordance with certain aspects of the presentdisclosure.

FIG. 6 is a flow diagram of example operations for sensing a multiphasefluid using EPR, in accordance with certain aspects of the presentdisclosure.

FIG. 7 is a flow diagram of example operations for controlling a systembased on EPR sensing, in accordance with certain aspects of the presentdisclosure.

FIG. 8 is a flow diagram of example operations for monitoring oil in apipeline system using EPR, in accordance with certain aspects of thepresent disclosure.

FIG. 9 is a flow diagram of example operations for monitoring multipleflow systems using EPR, in accordance with certain aspects of thepresent disclosure.

FIG. 10 is a flow diagram of example operations for field-widemonitoring using EPR, in accordance with certain aspects of the presentdisclosure.

FIG. 11A illustrates different asphaltene phases based on pressure,composition, and temperature, in accordance with the prior art.

FIG. 11B is a plot of asphaltene particle sizes based on pressure,illustrating operational safe zones, in accordance with certain aspectsof the present disclosure.

FIGS. 12A and 12B illustrate monitoring characteristics of a fluid basedon an example EPR signal, in accordance with certain aspects of thepresent disclosure.

FIG. 13 is a flow diagram of example operations for sensing a fluid in aflowing system using EPR, in accordance with certain aspects of thepresent disclosure.

FIG. 14 is a plot of AC conductivity versus frequency as a function ofasphaltene particle size, in accordance with certain aspects of thepresent disclosure.

FIG. 15 conceptually illustrates sensing a fluid flowing in a conduitusing a plurality of EPR devices, in accordance with certain aspects ofthe present disclosure.

FIG. 16 conceptually illustrates an example EPR measurement system usinga mobile EPR device, in accordance with certain aspects of the presentdisclosure.

FIG. 17A is a cross-sectional view of an example mobile EPR devicehaving multiple EPR sensors, in accordance with certain aspects of thepresent disclosure.

FIG. 17B is a cross-sectional view of an example mobile EPR devicehaving a single EPR sensor and a valve, in accordance with certainaspects of the present disclosure.

FIG. 18 is a flow diagram of example operations for sensing a fluidflowing in a conduit, in accordance with certain aspects of the presentdisclosure.

DETAILED DESCRIPTION

Certain aspects of the present disclosure provide methods and apparatusfor closed-loop control of a system using one or more electronparamagnetic resonance (EPR) sensors located on-site and properties of afluid. EPR sensors may be used to measure certain properties associatedwith any of various suitable species. Furthermore, the properties ofthese species may be measured by EPR sensors disposed at any of varioussuitable locations in the production process. With such EPR sensorsinstalled, a change can be applied to the system, the EPR sensors canmeasure the effect(s) of the change, and then adjustments can be made inreal-time. This feedback process may be repeated continuously to controlthe system.

Refer now to the drawings wherein depicted elements are not necessarilyshown to scale and wherein like or similar elements are designated bythe same reference numeral through the several views.

Referring to the drawings in general, it will be understood that theillustrations are for the purpose of describing particularimplementations of the disclosure and are not intended to be limitingthereto. While most of the terms used herein will be recognizable tothose of ordinary skill in the art, it should be understood that whennot explicitly defined, terms should be interpreted as adopting ameaning presently accepted by those of ordinary skill in the art at thetime of filing the present disclosure.

It is to be understood that both the foregoing general description andthe following detailed description are exemplary and explanatory only,and are not restrictive of the invention, as claimed. In thisapplication, the use of the singular includes the plural, the word “a”or “an” means “at least one,” and the use of “or” means “and/or,” unlessspecifically stated otherwise. Furthermore, the use of the term“including,” as well as other forms, such as “includes” and “included,”is not limiting. Also, terms such as “element” or “component” encompassboth elements or components comprising one unit and elements orcomponents that comprise more than one unit, unless specifically statedotherwise.

Conventionally, a sample (e.g., of a fluid in a conduit) may be takenfrom a system and sent off to a laboratory for analysis of certainproperties measurable by EPR. Traditional EPR spectrometers havetypically been very large and are thus housed in a laboratory, ratherthan being available on location (e.g., at a production well orinjection well). However, this off-site analysis process is too slow toeffect a change in the system in real-time based on the sample.Furthermore, the analysis may not be reliable enough or consistentenough.

Accordingly, certain aspects of the present disclosure provide forclosed-loop control of the system using an EPR sensor located on-site.With such an EPR sensor, a change can be applied to the system, the EPRsensor can measure the effect(s) of the change, and then adjustments canbe made in real-time. This process can be repeated.

FIG. 1 is a block diagram of an example EPR spectrometer 100, inaccordance with certain aspects of the present disclosure. The EPRspectrometer 100 may generally use building blocks similar to those of atraditional EPR spectrometer. For example, the EPR spectrometer 100 mayinclude one or more magnets 101, a resonator 103, and a transceiver 107,which includes both transmit (TX) circuitry 108 and receive (RX)circuitry 109 (also referred to as a transmitter and a receiver,respectively). For certain aspects, the EPR spectrometer 100 may be apermanently fixed EPR device, while in other aspects, the EPRspectrometer 100 may be a mobile EPR device. Such a mobile EPR devicemay be capable of traversing a length of a conduit, either inside oroutside of the conduit. In the case of a mobile EPR device, it couldtake measurements while stationary or while traversing the conduit.

For certain aspects, the transceiver 107 may be a microwave transceiver,operating at frequencies between 300 MHz and 300 GHz, for example. TheTX circuitry 108 may include a frequency synthesizer 110 and a poweramplifier 111 coupled between the output of the frequency synthesizer110 and a circulator 106 (e.g., at port 1 thereof). The TX circuitry 108is coupled to the resonator 103 via the circulator 106, so that theenergy of the source transmission does not overwhelm the sensitivecircuits of the RX circuitry 109. The output of the circulator 106(e.g., at port 2) passes to the resonator 103, which creates a radiofrequency (RF) electromagnetic field 104 (B₁ field) whose magneticcomponent is largely perpendicular to that of the static DC magneticfield 102 (B₀ field or Zeeman field).

A magnetic field generator provides the DC magnetic field 102 utilizingmagnets 101, coils, or the like. The resonator 103 and sample chambertherein are placed inside the magnets 101 and/or coils that generate theDC magnetic field B₀. The sample chamber is designed to allow fluids toflow therethrough. The fluid flow might be that of a full tubular inwellsite equipment or a sidestream to which a subset of the main flowhas been directed. In a downhole apparatus, the fluid flow might be thatcoming from a specific interval of the reservoir, such as directed by adownhole control valve or similar device. The presence of the Zeemanfield introduces an energy difference ΔE between the two spin states ofan unpaired electron: parallel and anti-parallel to B₀, with ΔE beingproportional to B₀. At its resonant frequency, the resonator 103produces the RF magnetic field B₁. Using the notation h for the Planckconstant, then at that RF frequency (f) where hf equals ΔE (i.e., theLarmor frequency), spin transitions between the two up and down spinstates occur, resulting in absorption of RF energy in the sample. In areflection-type resonator, this results in a change in the level ofreflected power from the resonator. This reflected power from theresonator is coupled to the receiver via the circulator 106 (e.g., atport 3). For certain aspects, the receiver may include a low noiseamplifier (LNA) 112, a mixer 113 coupled to the output of the LNA 112and the output of the frequency synthesizer 110, and an amplifier 114coupled to the output of the mixer 113.

As noted by International Patent Application Publication No. 2016187300to Babakhani et al., entitled “Electron Paramagnetic Resonance (EPR)Systems with Active Cancellation” and filed May 18, 2016, the circulatormight not provide complete isolation between the TX and RX circuitry, inwhich case an active cancellation component may be added to the EPRspectrometer. The entire contents of WO 2016187300 are hereinincorporated by reference.

The resonator 103 may be excited with continuous wave or pulsedexcitation. In one aspect, the EPR sensor is a sensor that operates at 1GHz or higher. In other aspects, the EPR sensor may operate at lowerfrequencies. For certain aspects, the EPR sensor may operate in therange of 3-5 GHz.

It is known that the resonant frequency of a fluid-filled cavity changesdepending on the fluid properties therein, as does the efficiency of thecoupling of the electromagnetic field to the cavity. The pertinentelectrical parameters of the cavity are its dielectric and conductivityproperties, which combine into an effective permeability according tothe formula ε+iσ/ω, where ε is the ratio of electrical displacementfield to electric field, σ is the conductivity, and e^(−iωt) is thevariation of the field in time (i.e., ω is the radial frequency, equalto 2πf where f is excitation frequency). The displacement field can beout of phase with the electric field, in which case ε can be viewed as acomplex number (ε′+iε″), or else the imaginary component of ε can beincorporated into the conductivity. In this text, and as is common inthe electromagnetic community, the term “permittivity” is used to referto both the complex value ε+iσ/ω, and also to just the dielectriccomponent, ε. The intended meaning will be clear to a person havingordinary skill in the art. The term iωε″+σ is commonly called the ACconductivity.

When “considering polar particles in a solvent, the permittivity may beapproximated as ε=ε_(s)+(ε_(c)−ε_(s))/(1+(iωτ){circumflex over( )}(1−α))+iσ/ω, where ε_(s) is solvent permittivity (e.g., hexane),ε_(c) is the crude component (e.g., asphaltene), α representsdistribution of relaxation times, and τ is the average relaxation time.Considering this expression, then in low frequency, the DC conductivitycomponent will dominate the AC conductivity, whereas as the frequencyincreases, then dipole relaxation will dominate as ε” increases withfrequency. This permittivity model was first proposed in Cole, K. S. etal., “Dispersion and Absorption in Dielectrics,” J. Appl. Phys., 9,341-351 (1941).

The magnetic properties of the medium are given by the permeability μ,which is the ratio of magnetic flux intensity B to the magnetic fieldintensity H. In air, the permeability is denoted μ₀. More generally onecan write μ=μ₀ (1+χ), where χ is termed the “susceptibility.” The B andH fields may be out of phase, in which case μ and χ are also complexnumbers. The imaginary component of χ is called its “AC magneticsusceptibility.” A classical interpretation of the EPR signal is thatthe applied magnetic field induces a change in the AC magneticsusceptibility. Knowledge of ε, σ, and μ can be used to identify fluidcomponents; for example, ε is about 80 in water, 2-5 in oil, and 1 in agas. σ will be virtually zero in hydrocarbons, but nonzero if there is amix of salty brine water along with the oil. μ will typically be closeto 1, but magnetic particles (e.g., from the wall of iron tubulars orfrom some minerals) can increase μ.

FIG. 2 is a block diagram of an example EPR system 200, in accordancewith certain aspects of the present disclosure. As shown, the EPR system200 comprises five modules: a high power programmable current source202, a power module 204, a controller module 206, a transceiver module208, and a resonator assembly 210. The high power programmable currentsource 202 may be implemented by a power supply with, for example, again of 5 A/V capable of 10 A with a 100 mH load. For certain aspects,an appropriate level of accuracy is 0.1% (±0.01 A). The output of thisprogrammable current source 202 feeds a magnet 211 in the resonatorassembly 210 to control the magnetic field. The controller module 206may be capable of outputting a control voltage (e.g., ranging from 0 Vto 2 V) to control the programmable current source 202. The power module204 may be a system capable of transforming mains electricity (e.g., 120VAC at 60 Hz) to one or more DC voltages (e.g., 12 VDC, 5 VDC, and/or5.5 VDC) for use in the EPR system 200. The transceiver module 208 maybe an EPR frequency board, capable of generating an RF signal for aresonator in the resonator assembly 210. Two board options may beconsidered for the transceiver module: an integrated circuit (IC)transceiver board and a discrete component transceiver board. Forexample, the discrete component transceiver board may use a 12 VDC powersupply voltage output by the power module 204. Alternatively, the ICtransceiver board may use a 5 VDC power supply voltage, which may bebuffered through the controller module 206.

The EPR system 200 may also include a human-machine interface (HMI) 212,such as a computer or any of various other devices (e.g., a tablet, asmartphone, and the like) with a suitable processing system, a display,and means for inputting instructions (e.g., a keyboard, mouse, stylus,touchscreen, and the like). The HMI 212 is capable of sending commandsto and receiving data from the controller module 206 (e.g., via aUSB/UART bridge 214 or via wireless communications, such as WiFiaccording to IEEE 802.11).

As shown in FIG. 2, the EPR system 200 may remain in continuous fluidcommunication with equipment at a wellsite, such as a wellhead 216disposed at the surface and/or production tubing 218 disposed in awellbore. The production tubing 218 may be one of multiple tubulars inthe wellbore. It is not uncommon, for example, that the productiontubing 218 is contained within a number of strings of casing (notshown). The wellhead 216 as drawn figuratively represents the connectionbetween a surface production pipeline 220 (which may be a subseapipeline) and the production tubing 218. As is well known in theindustry, wellheads typically have a number of sample ports thereon,which allows an operator access to the fluid flowing from a reservoir.During production, the flow path from the production tubing 218 throughthe wellhead 216 to the pipeline 220 is generally maintained as apressure barrier to prevent reservoir fluids from polluting the air andground nearby. Consequentially, the fluid communication channels 222,224 from the wellhead 216 to the resonator assembly 210 and back shouldbe able to withstand internal fluid pressure. The connections of thechannels 222, 224 to the wellhead 216 may be permanently welded or maybe hose connections that are certified for exposure to oilfield fluidsand pressures.

As drawn, the fluid connection for the channels 222, 224 is madedownstream of the wellhead 216 and upstream of the surface pipeline 220,but other configurations may be utilized, which will be clear to thoseskilled in the art. For example, the connections may be located furtherdownstream, such as in the vicinity of a pipeline manifold or at samplepoints along a pipeline as the pipeline transfers fluid from thewellbore to a refinery or vessel. Alternatively, the connections may bebelow the wellhead 216, such as in a scenario where the resonatorassembly 210 is incorporated as an in-well sensor.

As illustrated in FIG. 3, the HMI 212 may be some significant distanceaway from the wellhead 216. In this case, the HMI 212 may be incommunication with a portion of the wellsite equipment by means of thecloud and/or other communications network (e.g., WiFi according to theIEEE 802.11 standard). Indeed, in a typical oilfield setting, somecomponents may be positioned close to the wellbore, while others mayneed to be located relatively far away. RF components, such as theresonator assembly 210 and the transceiver module 208, should betypically spaced within a few feet of each other. To keep the channels222, 224 short, the resonator assembly 210 may most likely also bepositioned within a few feet of the wellhead 216. This means that theseRF components may most likely be enclosed in one or more explosion-proofhousings 302 to avoid any safety issues, should there be accidentalrelease of hydrocarbon at the wellhead 216. The power supplies (e.g.,the high power programmable current source 202 and the power module204), audio-frequency devices, etc. can be some distance removed fromthe wellhead without issue, so these components need not be inexplosion-proof housing(s), but might benefit from being in housings 304to provide insulation from the rain, snow, heat, etc. The proximatecomponents (e.g., in the housing(s) 302) may include one or morejunction boxes 303. Similarly, the remote components (e.g., in thehousing(s) 304) may include one or more junction boxes 305 for couplingto the junction boxes 303 via a cable 306. For certain aspects, thecable 306 may be a multicore armored cable.

FIG. 4 is a block diagram of an example EPR system 400 with a separator402 and a pump 404 to increase the sensitivity of an EPR spectrometer toa particular component of a multiphase fluid from a wellbore, inaccordance with certain aspects of the present disclosure. The separator402 may be used to partially separate multiple phases from themultiphase fluid received from the wellhead 216 via the fluidcommunication channel 224. For example, the opening and closing of oneor more valves in or associated with the separator 402 may be controlledto temporarily store the multiphase fluid in the separator, allow timefor the separator to separate at least a portion of one phase from oneor more other phases in the multiphase fluid, and permit the resultingfluid to enter the resonator assembly 210 for performing EPRspectroscopy. For example, the separator 402 may receive a multiphasefluid that is 98% water and 2% oil and generate a fluid that is 20% oiland 80% water. In this manner, the multiphase fluid reaching theresonator cavity have a higher percentage of oil, such that theparamagnetic species of interest in the oil (e.g., asphaltene) will havea higher concentration, thereby resulting in an EPR spectrometer withincreased sensitivity.

For certain aspects, the separated portion of the one phase may beremoved from the separator 402 by the optional fluid access 410. Thepump 404 may be used to pump the multiphase fluid from the wellhead 216into the separator 402 via the fluid communication channel 224. Thepressure and/or temperature of the resulting fluid in the fluidcommunication channel 222 may be measured by one or more gauges 408.

For certain aspects, an injection line 406 may be disposed in thewellbore (e.g., a production well), which may run adjacent to theproduction tubing 218. For other aspects, the injection line 406 may bedisposed in a different wellbore (e.g., an injection well). A fluid(e.g., a gas, such as carbon dioxide (CO₂), or an inhibitor) may beinjected into the injection line 406 via an injection valve 407, whichmay be located at the wellhead 216.

For certain aspects, the separator 402 may operate based on gravity andthe natural separation of an unstable emulsion (e.g., of oil and water)or other colloid that occurs over time. For other aspects, the separator402 may break the emulsion through the addition of a chemical component.In this case, the chemical component may be added, for example, via theinjection valve 407 or another port at the wellhead 216. In the case ofa multiphase fluid (e.g., a colloid) with a gas phase, the gas may bevented out (e.g., via the fluid access 403 or another port) before theremaining fluid is allowed to proceed to the resonator assembly 210(e.g., by controlling the valves in the separator).

FIG. 5 is a flow diagram of example operations 500 for controlling asystem based on EPR sensing, in accordance with certain aspects of thepresent disclosure. The operations 500 may begin, at block 502, bymeasuring a characteristic of a fluid in a system using an EPR sensor.At block 504, an operating parameter associated with the system isadjusted based on the measured characteristic of the fluid. Theoperations 500 may be repeated to effect closed-loop control of thesystem using the EPR sensor.

Any of various species in the fluid may be measured by the EPR sensor.For example, the species being sensed may include free radical andtransition metal ions, such as asphaltene (free radicals), scales, ironoxides, iron carbonates, iron sulfides, and tracers that have an EPRsignature.

The EPR sensor may provide a spectroscopic view of the paramagneticcomponents of the sample, but may also have additional sensors thereon.For example, the EPR sensor may derive permittivity, conductivity,density, viscosity, pressure, and/or temperature. In the case ofpermittivity, the EPR sensor may derive a spectrum of complexpermittivity values over a frequency range.

The EPR sensor may be disposed at any of various suitable locations(e.g., to implement the operations 500). For example, the EPR may belocated downhole, at a wellhead producer (i.e., the wellhead of aproduction well), at a wellhead injector (i.e., the wellhead of aninjection well), at a header or gathering facility, at a test separatoror other separator, adjacent to a pipeline, at a processing facility, ata storage, at an input to a refinery, or in the refinery process.

In this manner, the species of interest may be continuously monitoredthroughout a field or a process, at one or more locations as desired.Furthermore, the system can be adjusted in real-time based on thecharacteristics of the species measured with the EPR sensor(s).

For example, the EPR sensor may be positioned at a wellhead (e.g., of aninjection well or a production well) to measure asphaltenes. Chemicalsmay be injected into the well, and oil with asphaltenes therein may riseto the surface. The EPR sensor will allow for measurements of theresulting asphaltenes, so the amount of chemicals being injected can beadjusted accordingly. For example, if an insufficient amount of aparticular chemical is being injected, the EPR sensor may measure adecrease in surface asphaltenes in real-time, and the chemical injectionmay be increased based on these measurements. Alternatively, ifexcessive chemicals are being injected, the operator and/or the EPRsystem can decrease those chemicals, for example, until a decrease inasphaltene is sensed, which may thereby identify an optical amount ofchemicals. With this closed-loop control, an optimal amount of chemicalsmay be injected, which should save money. In other words, certainaspects of the present disclosure provide an online monitoring EPRsensor (e.g., at the wellhead) that generates a signal to optimize, orat least adjust, chemical injection.

Example Sensing of a Multiphase Fluid Using EPR

Knowing component percentage in a complete multiphase fluid may not besufficient to guide subsequent decision making at the well (e.g., adecision to change chemical injection parameters, type of chemical,etc.) because the appropriate measurement may be the percentage in theoil phase, not the percentage in the combined multiphase flow. Forexample, consider that a certain crude oil has 5% asphaltene as it exitsthe sandface of the reservoir and then commingles with water as itreturns to the surface, such that a surface measurement gives 90% waterand 10% oil, where 5% of that oil is asphaltene (i.e., 0.5% of the totalfluid). Now consider that chemical instability or pressure drop causesmost of the asphaltene to drop out of the oil, so that at surface ameter will read 90% water and 10% oil, where 1% of the oil isasphaltene. In this scenario, a correct response might be to increaseinjection of solvent into the well, or to get ready for an interventionwith a coiled-tubing unit to unclog the well, because the bulk of theasphaltene has not made it to the surface. For a different scenario,suppose that the water cut increases with no increase in drop-out, sothat the surface meter reads 98% water and 2% oil, where 5% of that oilis asphaltene. In this scenario, a correct response might be to reducethe amount of solvent. Both scenarios give 0.1% asphaltene ratio. If theonly measurement available was coming from EPR sensing of the totalfluid, then it may be quite difficult to make a guided decision. None ofthe references cited herein anticipate using spectrometry to extract theEPR signal of a single component of a multiphase fluid. This ability maybe even more useful when employing the EPR signal to drive a controlsystem or feedback loop, as described herein.

FIG. 6 is a flow diagram of example operations 600 for sensing amultiphase fluid, in accordance with certain aspects of the presentdisclosure. The operations 600 may be performed by an EPR system, forexample.

The operations 600 may begin, at block 602, by extracting at least onecharacteristic of at least one of a first phase or a second phase in themultiphase fluid in a flowing system. At block 604, EPR spectroscopy maybe performed (e.g., using an EPR spectrometer) on at least a portion ofthe multiphase fluid to generate an EPR spectrum. At block 606, thesystem may determine at least one property of the multiphase fluid basedon the EPR spectrum and the at least one characteristic.

According to certain aspects, the operations 600 may further involveadjusting an operating parameter of the flowing system based on the atleast one property at optional block 608. For certain aspects, theoperations 600 may further entail repeating the extracting at block 602,the performing at block 604, the determining at block 606, and theadjusting at block 608 for automated closed-loop control of theoperating parameter. These blocks may be repeated one or more times. Theoperating parameter may include a rate or a volume of fluid injectioninto the flowing system. Additionally or alternatively, the operatingparameter may include a pressure, a type, or a concentration of aninjected fluid introduced into the flowing system.

According to certain aspects, the flowing system comprises a system forhydrocarbon recovery operations. In this case, the first phase may be anoil component of the multiphase fluid, and the second phase may be awater component or a gas component of the multiphase fluid. For certainaspects, the system for hydrocarbon recovery operations includes awellhead. In this case, the performing at block 604 may involveperforming the EPR spectroscopy on the at least the portion of themultiphase fluid at or adjacent the wellhead. For certain aspects, theat least one characteristic includes a volume fraction of the oilcomponent. In this case, the at least one property may include aconcentration of asphaltene in the oil component (as opposed to aconcentration of asphaltene in the multiphase fluid).

According to certain aspects, the operations 600 may further entailseparating at least a portion of the second phase from the multiphasefluid (e.g., 95% water and 5% oil) to leave a remaining fluid (e.g., now80% water and 20% oil). For certain aspects, the at least the portion ofthe multiphase fluid includes the remaining fluid, and in this case, thedetermining at block 606 may involve determining at least one propertyof the remaining fluid.

According to certain aspects, the operations 600 may further includecontrolling one or more valves to at least one of: (1) store themultiphase fluid in a separator, (2) separate at least a portion of thesecond phase from the multiphase fluid, or (3) allow the at least theportion of the multiphase fluid to enter a resonator from the separatorfor performing the EPR spectroscopy at block 604.

According to certain aspects, the operations 600 may further involvedetermining at least one electromagnetic attribute of the at least theportion of the multiphase fluid. In this case, determining the at leastone property of the multiphase fluid at block 606 may entail determiningthe at least one property of the multiphase fluid based on the EPRspectrum, the at least one characteristic, and the at least oneelectromagnetic attribute. For certain aspects, determining the at leastone electromagnetic attribute is based on performing the EPRspectroscopy at block 604. In this case, the at least oneelectromagnetic attribute includes at least one of a conductivity, adielectric property, a magnetic susceptibility, or a magneticpermeability, of the at least the portion of the multiphase fluid.

According to certain aspects, the operations 600 may further includeadjusting an operating parameter of the flowing system based on adeviation of a current value of the at least one property from abaseline value of the at least one property. For certain aspects, thebaseline value was generated by: (1) repeating the extracting at block602, the performing at block 604, and the determining at block 606 overtime to generate multiple values of the at least one property; and (2)deriving the baseline value based on the multiple values of the at leastone property. For certain aspects, the operations 600 may furtherinvolve: (1) repeating, after the adjusting, the performing the EPRspectroscopy at block 604 to generate an updated EPR spectrum; and (2)identifying a change in the updated EPR spectrum from a previouslygenerated EPR spectrum.

According to certain aspects, at least one property includes aconcentration of asphaltene in the multiphase fluid.

According to certain aspects, the at least one characteristic includesat least one of a volume fraction of the first phase or a volumefraction of the second phase.

FIG. 7 is a flow diagram of example operations 700 for controlling asystem based on EPR sensing, in accordance with certain aspects of thepresent disclosure. The operations 700 may be performed by an EPRsystem, for example.

The operations 700 may begin, at block 702, by measuring acharacteristic of a fluid with an EPR sensor (e.g., an EPRspectrometer). For example, the characteristic(s) may include asphalteneparameters, such as concentration, particle size, and/or behavior. Forcertain aspects, a baseline thereof may also be established at block 702or prior thereto.

At block 704, an oilfield operation may be performed to perturb aproduced fluid. Example oilfield operations may include, but are notlimited to, performing an intervention, scraping tubing walls, injectinginhibitor and allowing the inhibitor to soak, changing injection ratesor injected chemicals (e.g., at the surface), changing wellheadpressure, changing injected enhanced oilfield recovery (EOR) fluid(e.g., in a nearby well), and the like.

At block 706, a change from the baseline may be measured. For certainaspects, the EPR sensor may be used to measure additional data, and achange in the data may be determined. For example, the change from thebaseline may include a change in concentration, volatility, spectrum,and/or other behaviors.

At block 708, the measured data may be used to update management of thewell (e.g., by adjusting an operating parameter). For example, atreatment change may be initiated, which may include, for example, achange in the level of inhibitor(s) and/or other chemical(s) injected, achange in the type or concentration of the injected fluid, a change inthe operational condition (e.g., change pressure, temperature, or otherparameter), or a change in an injection parameter (e.g., rate). Morespecifically, the system may be tuned by increasing or reducing thevolume or rate of a chemical inhibitor, not only ascertaining the rightamount (or rate) of a chemical for the condition, but also tuning perother (changing) operational conditions. Furthermore, the system may betuned by (continuously) adjusting one or more operational conditions.For example, by increasing pressure in the system, an operator may beable to keep asphaltenes from coming out of solution, which mayeliminate the use of chemicals in some scenarios. For certain aspects, anew baseline may be created at block 710. Then, the operations 700 maybe repeated, starting with block 704 as illustrated in FIG. 7. Theability to continuously measure in real-time allows an operator to tryvarious adjustments to the system, analyze the effects, and trysomething different (e.g., different types of inhibitors and/ordifferent types of operation modes).

Quality and (Flow) Monitoring of Sales Oil

In the case of a pipeline as an example conduit, one or more EPR sensorsmay be used for inspection and quality control of the pipeline. A fluidsupplier (e.g., an oil or gas company) may claim that the fluid beingsupplied has a particular composition. The pipeline company may want tomonitor that the actual fluid being supplied matches the compositionclaims made by the fluid supplier and look for changes. If thecomposition of the fluid does not match what has been claimed, thepipeline company can ask the fluid supplier to make adjustments.

FIG. 8 is a flow diagram of example operations 800 for monitoring oil ina pipeline system using EPR, in accordance with certain aspects of thepresent disclosure. The operations 800 may begin, at block 802, bymonitoring the asphaltene level in the oil at a location in the pipelinesystem using EPR spectroscopy (e.g., using a fixed or mobile EPRdevice). For example, the location may be at the point of entry into thepipeline system or along the length of the pipeline system. For certainaspects, a baseline characteristic of the oil may be established atoptional block 804. In this case, this oil's baseline may be comparedwith those of other fluids (e.g., oils) entering the same pipelinesystem, if the fluids are commingled. At block 806, the system maydetermine whether the asphaltene level is within specifications. Forcertain aspects, the system may report the results. If the asphaltenelevel is determined to be outside the specifications at block 806, thenat block 808, the system may output an indication and/or perform anaction to bring the asphaltene level within the specifications. Thisdetermination may be performed concurrently with a determination ofother parameters of the crude oil, such as pH, level of sulfur, etc.

Field-Wide Monitoring of Asphaltene Using EPR

According to certain aspects, field-wide monitoring of asphaltenes maybe performed using EPR sensors. Using EPR sensors in this manner, theremay be an observed, distinct difference in asphaltenes between carbondioxide (CO₂) flood areas and water (H₂O) flood areas. Areas exposed toCO₂ over time may have more deposited asphaltenes than areas lessexposed to CO₂. Therefore, asphaltene measurement may be used as a toolto determine injection patterns for enhanced oil recovery (EOR). In thismanner, the effects of CO₂ injection (e.g., where the CO₂ is going) maybe determined based on changes in asphaltene concentration as measuredby the EPR sensors (e.g., at the wellheads).

For certain aspects, a survey of the wells in the field may beperformed, prior to CO₂ injection (e.g., to establish a baseline). Then,asphaltene concentrations may be monitored over time on differentproducers. Based on the asphaltene concentrations, operating parametersfor one or more of the wells may be adjusted. For example, the injectionpattern of CO₂ may be changed, or certain chemicals (e.g., polymers) maybe added in an effort to influence how CO₂ moves within the reservoir.

FIG. 9 is a flow diagram of example operations 900 for monitoringmultiple flow systems using EPR, in accordance with certain aspects ofthe present disclosure. The operations 900 may begin, at block 902, byperforming EPR spectroscopy on a fluid in each of a first group of flowsystems to generate a plurality of EPR spectrums. For each of the firstgroup of flow systems, at block 904, at least one property of the fluidmay be determined based on the EPR spectrum associated with the flowsystem.

According to certain aspects, the operations 900 may further involvecalculating, for one of the first group of flow systems at optionalblock 906, a deviation of a current value of the at least one propertyfrom a baseline value of the at least one property. For certain aspects,the baseline value of the at least one property is based on a pluralityof historic values of the at least one property for the first group offlow systems. For certain aspects, the baseline value was generated by:(1) repeating the performing at block 902 and the determining at block904 over time to generate multiple values of the at least one propertyfor each of the first group of flow systems; and (2) deriving thebaseline value based on the multiple values of the at least one propertyfor each of the first group of flow systems. For certain aspects, theoperations 900 may further entail adjusting an operating parameter of atleast one of a second group of flow systems, at optional block 908,based on the deviation of the current value of the at least one propertyfrom the baseline value of the at least one property. The second groupof flow systems may be different from the first group of flow systems.For certain aspects, the operating parameter includes a rate or a volumeof fluid injection into the at least one of the second group of flowsystems. Additionally or alternatively, the operating parameter includesa pressure, a type, or a concentration of an injected fluid introducedinto the at least one of the second group of flow systems. For certainaspects, the multiple flow systems comprise multiple systems forhydrocarbon recovery operations in a field. In this case, the firstgroup of flow systems may include multiple production wells in thefield, and the second group of flow systems may include multipleinjection wells in the field.

According to certain aspects, the operations 900 may further involverepeating the performing at block 902 and the determining at block 904over time to generate multiple values of the at least one property forat least one of the first group of flow systems. In this case, theoperations 900 may also include correlating the multiple values of theat least one property for the at least one of the first group of flowsystems with other data for the at least one of the first group of flowsystems. For certain aspects, the other data includes at least one ofproduction history data, seismic data, or geology data for the at leastone of the first group of flow systems. For certain aspects, theoperations 900 may further entail adjusting an operating parameter of atleast one of a second group of flow systems based on the correlation.The second group of flow systems may be different from the first groupof flow systems.

According to certain aspects, the multiple flow systems comprisemultiple systems for hydrocarbon recovery operations in a field. In thiscase, the first group of flow systems includes multiple production wellsin the field. For certain aspects, the fluid in each of the first groupof flow systems comprises oil. In this case, the at least one propertymay include a concentration of asphaltene in the fluid or aconcentration of asphaltene in the oil.

According to certain aspects, the operations 900 may further entaildetermining, for one of the first group of flow systems, at least oneelectromagnetic attribute of the fluid. In this case, determining the atleast one property of the fluid at block 902 involves determining the atleast one property of the fluid based on the EPR spectrum and the atleast one electromagnetic attribute. For certain aspects, determiningthe at least one electromagnetic attribute is based on performing theEPR spectroscopy. In this case, the at least one electromagneticattribute may include at least one of a conductivity, a dielectricproperty, a magnetic susceptibility, or a magnetic permeability, of thefluid in the one of the first group of flow systems.

According to certain aspects, the fluid in each of the first group offlow systems comprises a multiphase fluid.

According to certain aspects, the operations 900 may further involveadjusting an operating parameter of one of a second group of flowsystems. In this case, the multiple flow systems may include multiplesystems for hydrocarbon recovery operations in a field, the first groupof flow systems may include multiple production wells in the field, andthe second group of flow systems may include multiple injection wells inthe field. For certain aspects, the operations 900 may further entail,after the adjusting, performing EPR spectroscopy on the fluid in each ofthe first group of flow systems to generate a plurality of updated EPRspectrums; determining, for each of the first group of flow systems, theat least one property of the fluid based on the updated EPR spectrumassociated with the flow system; comparing the plurality of updated EPRspectrums with the previously generated plurality of EPR spectrums; anddetermining reservoir continuity in the field based on the comparison.

As a specific example, FIG. 10 is a flow diagram of example operations1000 for field-wide monitoring of asphaltene using EPR, in accordancewith certain aspects of the present disclosure. The operations 1000 maybegin, at block 1002, by measuring asphaltene at multiple wellheadlocations throughout a field using EPR spectroscopy. The asphaltene maybe measured at the surface or subsurface at the wellhead locations.These measurements may be more relevant in more mature fields with someform of EOR operation starting or ongoing (e.g., using secondary ortertiary methods).

At block 1004, a baseline may be established throughout the field.Depending on the nature of the field, the baseline may take a fewdifferent forms. In a new field, the baseline may represent a startingpoint, whereas in an older field, the baseline may represent a pointmoving forward.

At block 1006, based on the measured asphaltene data, zones andreservoir connectivities (and/or disconnectivities) may be establishedthroughout the field. For certain aspects, this data may be correlatedwith other data, such as production history, geology, seismic data,and/or other available data.

At block 1008, one or more EOR strategies may be established, based onthe information determined at block 1006. For example, these strategiesmay include fluid injection (e.g., of water or gas) or applyingpumping/extraction pressures.

At block 1010, asphaltene may be measured in at least a portion of thefield (e.g., partially or fully throughout the field at surface orsubsurface). At block 1012, the one or more EOR strategies may beadjusted, based on the measured asphaltene. For certain aspects, blocks1010 and 1012 may be repeated as desired.

For example, an amount of injected CO₂ may be increased (e.g., at block1012) in a certain injection well (e.g., #5 well). In response, theasphaltene concentration at a particular well (e.g., #2 production well)drops, indicative of asphaltene deposition (e.g., as measured at block1010). Therefore, the EOR strategy may be adjusted (e.g., at block 1012)to decrease the amount of CO₂ injected and/or inject water instead(e.g., into #5 well). This may be done until the asphalteneconcentration in the particular well (#2) begins to rise.

As another example, the operations 1000 may be used to map CO₂distribution within a reservoir. For example, an operator may suspect anarea with significantly lowered asphaltene at the well has hadsignificantly more exposure to CO₂, either over time or by volume (morebreakthrough).

Monitoring asphaltenes can be used to map CO₂ EOR floods (andpotentially water floods). For CO₂ flood, the asphaltene content may bemeasured (e.g., at block 1002) before the addition of CO₂. After a CO₂flood is applied, an EPR system may be used to measure the change of theasphaltene content at each well (e.g., at block 1010), which representsthe relative amount of CO₂ reaching each well. This method shows the CO₂connectivity between wells and can be used to optimize, or at leastadjust, the CO₂ injection pattern (e.g., at block 1012).

More specifically, in some scenarios, there may multiple production andinjections wells in a field, where EPR sensors may be implemented at aportion of these wells. Increasing the CO₂ injection in one injectionwell (e.g., #5 well) may cause the asphaltene content as measured by theEPR sensors to drop in a group of production wells (e.g., #2, #11, and#13 wells), but not change the asphaltene content in any of the otherwells in the field. This may lead to the inference that the reservoirintersected by the injection well has good connectivity to reservoirintersected by the particular group of production wells, but not toother wells. Based on such inferences, reservoir continuity may bedetermined.

In the case of an injector, an injection fluid (e.g., carbon dioxide(CO₂) or water) may be injected into an injection well via the injector.This injection fluid may show up in the production fluid being producedfrom the production well and may be separated out by a separator, forre-use in the injection well. However, the injection fluid coming out ofthe production well may have some species of interest (e.g., asphaltenes(in gas or solid phase)) that may be undesirable (e.g., because thisspecies can cause problems in the injection well. Therefore, theinjection fluid coming out of the production well or out of theseparator may be filtered, and an EPR sensor may be used to monitor theinjection fluid (e.g., at the wellhead injector).

Asphaltene PVT Measurement and Monitoring Using EPR

According to certain aspects, compositional data from a subject fieldmay be used to establish the asphaltene boundaries for core EORconditions (e.g., injected water or gas). The asphaltene boundaries(e.g., upper and lower boundaries) may be based on apressure/volume/temperature (PVT) chart, such as PVT charts 1100 and1120 shown in FIG. 11A. The chart 1100 illustrates asphaltene phase as afunction of pressure and composition, whereas the chart 1120 illustratesasphaltene phase as a function of pressure and temperature.

EPR may be used to measure various parameters, two of which areillustrated in the chart 1130 of FIG. 11B. These parameters may include,for example: (1) the total asphaltene regardless of particle size (i.e.,bulk asphaltene); and (2) an envelope 1132 of the total dissolvedparticles (dots) to the envelope 1134 for the majority of theflocculated/large particles (triangles). Based on these two parameters,EPR can measure and help determine if a well or an area of a field staysinside the “safe” zones (above the upper boundary and below the lowerboundary of envelope 1132). Operational condition(s) (e.g., pressure)and/or injection condition(s) may be adjusted in an effort to stay inthe safe zones (e.g., according to the charts 1100 and 1120). Once safezone conditions are established, the EPR system may be used to monitorthe well and avoid operation out of the safe zones.

As shown in the plot 1200 of FIG. 12A, the shape of the EPR curve itselfprovides useful information. Babakhani '478 has disclosed that theheight of the anomaly, V_(pp), is indicative of the concentration of aparamagnetic component. The width of the anomaly, x_(pp), (measuredbetween points associated with the EPR signal peaks) is indicative of arelaxation time, also known as T2. Large particles will in generalcorrespond to a broader anomaly (i.e., a higher x_(pp)). Consequently,by monitoring the line width, the EPR system may be used to provide afurther indication that the conditions are moving out of the safe zone.More details on line-width analysis are given in Freed, J. H., et al.,“Theory of Linewidths in Electron Spin Resonance Spectra,” The Journalof Chemical Physics, vol. 39, (1963) p. 326.

Given the indication (e.g., represented as a check mark or a cautionsymbol) that the operation is moving out of the safe zones (e.g., with awider x_(pp)), then operational condition(s) (e.g., pressure) and/orinjection condition(s) may be adjusted in an effort to stay in the safezones (e.g., according to the charts 1100 and 1120). Once safe zoneconditions are established, the EPR system may be used to monitor thewell and avoid operation out of the safe zones.

Example EPR Monitoring Based on Change from a Baseline

Other EPR monitoring techniques may prove to be more exact thanmonitoring the anomaly width, as explained above for FIG. 12A. The plot1220 in FIG. 12B contains the same representative curve of EPR signalversus magnetic field as FIG. 12A, except that instead of deriving andusing line width, the algorithm determines and utilizes the peak-to-peakvoltage (V_(pp)). It is known that V_(pp) correlates to asphalteneconcentration. By taking a sample of crude oil and varying thepercentage of asphaltene therein, it is possible to derive a specificcorrelation. Taking real-time data from an EPR sensor and converting toasphaltene percentage gives the chart 1221 illustrating deviation of atrace 1224 representing an asphaltene concentration in oil from abaseline value 1222 over time.

It is to be noted, however, that a calibration (such as the correlationcalibration described above) is not mandatory. Instead, it may besufficient to consider the deviation from baseline. In other words, whenthe oil tracks the baseline, then the oil is in the safe zone, but whenthe EPR signal drops, then that is indicative of less asphaltene. Inthis case, the signal may be flagged as being outside the safe zone.

FIG. 13 is a flow diagram of example operations 1300 for sensing a fluidin a flowing system using EPR. The operations 1300 may begin, at block1302, by performing EPR spectroscopy, using an EPR spectrometer, on atleast a portion of the fluid to generate an EPR spectrum. At block 1304,at least one property of the fluid may be determined based on the EPRspectrum. At block 1306, a deviation of a current value of the at leastone property from a baseline value of the at least one property may becalculated.

According to certain aspects, the operations 1300 may further involve,at optional block 1308, adjusting an operating parameter of the flowingsystem based on the deviation of the current value of the at least oneproperty from the baseline value of the at least one property. Forcertain aspects, the operations 1300 may further include repeating theperforming the EPR spectroscopy to generate an updated EPR spectrum,after the adjusting at block 1308, and identifying a change in theupdated EPR spectrum from a previously generated EPR spectrum. Forcertain aspects, the operations 1300 may further entail repeating theperforming at block 1302, the determining at block 1304, the calculatingat block 1306, and the adjusting at block 1308 for automated closed-loopcontrol of the operating parameter. For certain aspects, the operatingparameter includes a rate or a volume of fluid injection into theflowing system. Additionally or alternatively, the operating parameterincludes a pressure, a type, or a concentration of an injected fluidbeing introduced into the flowing system.

According to certain aspects, the baseline value was generated by: (1)repeating the performing at block 1302 and the determining at block 1304over time to generate multiple values of the at least one property; and(2) deriving the baseline value based on the multiple values of the atleast one property.

According to certain aspects, the flowing system includes a system forhydrocarbon recovery operations. In this case, the fluid may includeoil. For certain aspects, the at least one property includes aconcentration of asphaltene in the fluid or a concentration ofasphaltene in the oil.

According to certain aspects, the flowing system comprises a system forhydrocarbon recovery operations including a wellhead. In this case, theperforming at block 1302 may entail performing the EPR spectroscopy onthe at least the portion of the fluid at or adjacent the wellhead.

According to certain aspects, the operations 1300 may further involvedetermining at least one electromagnetic attribute of the at least theportion of the fluid. In this case, determining the at least oneproperty of the fluid at block 1304 may include determining the at leastone property of the fluid based on the EPR spectrum and the at least oneelectromagnetic attribute. For certain aspects, determining the at leastone electromagnetic attribute is based on performing the EPRspectroscopy. In this case, the at least one electromagnetic attributemay include at least one of a conductivity, a dielectric property, amagnetic susceptibility, or a magnetic permeability, of the at least theportion of the fluid.

According to certain aspects, the fluid comprises a multiphase fluid.

Example Asphaltene and Paraffin Flocculation and Precipitation

In cases where the EPR sensor includes a complex permittivitymeasurement over a frequency range, the EPR system can identifyflocculation by analyzing the change in that frequency measurement thatoccurs as the polar components coalesce. For a practical application,there may be too many parameters to fit a full mixing model. Instead,according to certain aspects, a series of baselines may be developedfrom a sample of fluid from the well that is targeted with increasingalkane (e.g., n-heptane). FIG. 14 is an example plot 1400 showing thevariation of the imaginary component of permittivity (i.e., thedielectric loss) as a function of frequency. A frequency range has beenchosen such that in the lower frequencies, the conductivity componentwill dominate, whereas as the frequency increases, then dipolerelaxation will dominate. As the fluid enters into the warning “yellow”zone because of pressure or concentration changes, then the most polarcomponents may coalesce, and flocculation may begin. This induces achange in the characteristic shape of the curve. For example, in FIG.14, that characteristic is the presence of inflection point 1402 betweenthe range of lower frequencies 1406 and the range of upper frequencies1404.

Publications describing potential characteristics include Lesaint, C.,et al., “Properties of Asphaltene Solutions: Solvency Effect onConductivity,” Energy Fuels, 27 (1), (2013), pp. 75-81; Goual, L.,“Impedance of Petroleum Fluids at Low Frequency,” Energy and Fuels, 23,(2009), pp. 2090-2094; Penzes, S., et al., “Electrical conductivities ofbitumen fractions in non-aqueous solvents,” Fuel, 53, (1974), pp.192-197; Fotland, P., “Conductivity of Asphaltenes,” Structure andDynamics of Asphaltenes, Plenum: New York, 1998; Sheu, E. Y., et al.,“Frequency-dependent conductivity of Utah crude oil asphaltene anddeposit,” Energy Fuels, 18, (2004), pp. 1531-1534; Sheu, E. Y., et al.,“Asphaltene self-association and precipitation in solvents and ACconductivity measurements,” Asphaltenes, Heavy Oils and Petroleomics,Springer: New York, 2007; and Sheu, E. Y., et al., “A dielectricrelaxation study of precipitation and curing of Furrial crude oil,”Fuel, vol. 85, (2006) pp. 1953-1959. All of these papers are hereinincorporated by reference in their entireties.

Example operations for the technique may begin by taking a sample of oil(e.g., crude oil) and measuring EPR and dielectric spectral response forincreasing alkane. A frequency range may be identified in which aconductivity component can be seen for lower frequencies and a dipolemoment can be seen for higher frequencies (e.g., that the conductivityhas a region of negative slope versus frequency and a second region ofincreasing slope). Optionally, a concentration of alkane indicated toremove the dipole moment may be identified (so that the AC conductivityis monotonic decreasing over the entire frequency range). The dielectricvalues versus frequency may be monitored in real-time, and an alertindication may be generated if the dipole moment drops. This may becombined with the EPR sensor to generate another alert indication forany change in the paramagnetic species of interest.

In the case of paraffin buildup, the component precipitating isnonpolar. However, field experience shows that the paraffin buildup willalso precipitate out some of the polar asphaltene components, so thesame operations should apply.

Certain aspects of the present disclose provide apparatus and methods toenhance the interpretation of EPR data of a fluid including polarcomponents through the use of a measurement of complex permittivity as afunction of varying frequency. These may involve determining at leastone characteristic of the permittivity curve versus frequency thatidentifies a consolidation of the polar components.

Example Monitoring Using a Mobile EPR Device

As described above (e.g., with respect to FIG. 8), in the case of apipeline or other conduit, one or more EPR sensors may be used forinspection and quality control of the multiphase fluid flowing in thepipeline. A fluid supplier (e.g., an oil or gas company) may claim thatthe fluid being supplied has a particular composition. The pipelinecompany (or other company receiving the fluid at an end of the pipeline)may wish to monitor the fluid to ensure that the actual fluid beingsupplied matches the fluid composition claimed by the fluid supplier andlook for changes.

FIG. 15 illustrates multiple EPR systems 200 located along the length ofa pipeline 220 or other conduit. In this case, chemical or otherinformation may be obtained at those points along the pipeline, butthere may be no information about the location of flow events,deposition, etc. between the EPR systems 200. While the variousmeasurements from the EPR systems 200 may be useful in determining anoccurrence of an event (e.g., corrosion of the conduit), determining anexact location of the event may be difficult. Similarly, it might bepossible, for example, to determine that some deposition had occurredupstream of one of the devices 200, but not necessarily where thatdeposition had occurred. For certain aspects, measurements from thevarious EPR systems 200 may be combined to improve spatial resolution ofthe measurements.

Certain aspects of the present disclosure provide a mobile EPR devicecapable of being conveyed along a length of a conduit by a fluid flowingin the conduit. The mobile EPR device may include an EPR sensor formaking an EPR measurement and, for certain aspects, may include one ormore other sensors for making other measurements. The conduit may be apipeline (e.g., production pipeline 220) or any of various othersuitable tubulars. The fluid may be a liquid, a gas, or a multiphasefluid, for example; the fluid need not be oilfield related. For certainaspects, the mobile EPR device may be implemented as an intelligentpipeline “pig” (also known as a smart pig) that can be inserted into andextracted from a section of the pipeline or other conduit. The smart pigmay be conveyed (e.g., pushed) by the flow of fluid in the conduit, suchas by pumped multiphase fluid from an oilfield. Methods of deployingsuch pigs are well known in the industry; for example, see U.S. Pat. No.6,022,412 to Bath et al., entitled “Method of remotely launching subseapigs in response to wellhead pressure change,” and U.S. PatentPublication No. 2016/0169436 to Sander et al., entitled “Automated piglaunching system.” The entire contents of both these patents are herebyincorporated by reference. In some configurations, it is possible forthe pig to remain continuously attached to a cable near the launchpoint, in which case communication can be made along the cable. The pigmay then be retrieved by pulling back on the cable. In other scenarios,the pig may be retrieved at some point downstream of a launch point.

FIG. 16 illustrates an example EPR measurement system 1600 using anexample mobile EPR device 1601, in accordance with certain aspects ofthe present disclosure. The mobile EPR device 1601 (e.g., a smart pig)is designed to operate within a conduit, such as a subsea or surfacepipeline (e.g., a pipeline 220, as shown). The conduit includes apipeline wall 1602, a first section 1607 of pipeline, and a secondsection 1608 of pipeline, subsequent to the first section. Asillustrated, a fluid (e.g., oil, gas, or a multiphase mixture, such asan oil-water mixture) flows within the pipeline wall 1602 from the firstsection 1607 to the second section 1608. Fluid at 1605, which isupstream of the mobile EPR device 1601, is at pressure P. Fluid at 1606,which is downstream of the mobile EPR device 1601, is at pressure P-ΔP(i.e., the pressure downstream of the mobile EPR device 1601 is lowerthan the pressure upstream of the mobile EPR device 1601). In accordancewith certain aspects of the present disclosure, the mobile EPR device1601 is conveyed through the conduit as a result of this pressuredifference. Such a pressure difference may convey the mobile EPR device1601, unless the mobile EPR device 1601 includes an additionalpropulsion mechanism such as seen, for example, in U.S. Pat. No.7,182,025 to Ghorbel et al., entitled “Autonomous robotic crawler forin-pipe inspection.” The mobile EPR device 1601 may use an EPR system(e.g., similar to the EPR system 200 illustrated in FIG. 2) to measurespecies within the fluid in the conduit. Species to be detected might beflowing within the fluid or might have been deposited on the interior ofthe pipeline wall 1602 (e.g., scale). The mobile EPR device 1601 maydetect species 1603 that are soluble in the fluid, and/or species 1604that are recently removed from the wall 1602. An optional remotelyoperated vehicle (ROV) 1610 (e.g., a drone) may be used to locate and/orcommunicate with the mobile EPR device 1601 from outside of the conduit.

In certain aspects of the present disclosure, the mobile EPR device 1601may include a fluid communication path such that some fluid fromupstream of the mobile EPR device at 1605 is able to move downstream ofthe mobile EPR device 1601 to 1606.

With a mobile EPR device, EPR and/or other measurements may be madealong a length of the conduit from inside the conduit. The measurementsmay be made continuously or intermittently as the mobile EPR devicetraverses the length or portions of the length of the conduit. The EPRmeasurements may be made of the fluid or of depositions along thepipeline wall 1602. Indeed, it is noted that a common function of apumped pig is to scrape along the internal surface of a pipeline, inwhich case the pumped pig could be removing deposition from thatsurface. It is thus of interest for the mobile EPR device 1601 to bemeasuring properties of fluid and/or of components that have beenremoved from the wall by the mobile EPR device 1601. It is also notedthat in a pumped scenario that a point, at 1605, upstream of the mobileEPR device 1601 will be at a higher pressure than a point, at 1606, thatis downstream of the mobile EPR device 1601.

The measurements from the EPR sensor and/or other sensors may be storedin a memory of the mobile EPR device 1601. Such measurements may becommunicated via a cable (e.g., a conductive wire and/or a fiber-opticcable) attached to the mobile EPR device 1601, and/or communicatedwirelessly (via telemetry). Pig signaling techniques may be used toindicate that the mobile EPR device 1601 has left the launcher, arrivedin a receiver, or passed a certain point in the pipeline. As an example,see EP0254503 to Addis et al., entitled “Pig Signaller,” and associatedcitations. For example, the measurements may be transmitted to areceiver via a transmitter (e.g., TX circuitry 108) of the mobile EPRdevice 1601. Additionally, the position of the mobile EPR device 1601may be communicated using any of various suitable techniques. Forexample, in a subsea configuration, the mobile EPR device maycommunicate its position to an ROV 1610, while for a pipeline above theground the communication could be to a drone. In both these scenarios,the sensing tool or pig may need to communicate through the metalhousing of the pipeline. This can be done acoustically or via lowfrequency electromagnetic (EM) transmission. For example, see F. N.Sibai, “Modelling of Wireless Acoustic in-pipe robot communicationthrough the steel pipeline,” International Journal of Mechatronics,Electrical and Computer Technology, Vol. 5 (16), July 2015, pp.2229-2238 for an acoustic communication method and the product portfolioof PolyEurope for low frequency EM transmission. PolyEurope is based inthe Netherlands at Kruiwiel 14, 4191 T J Geldermalsen and maintains thewebpage www.polyeurope.com.

A mobile EPR device 1601 may be able to get to areas of the conduit thatmight otherwise be inaccessible. For certain aspects, the EPRmeasurements made by the mobile EPR device 1601 may supplementmeasurements from one or more other EPR sensors deployed outside theconduit along the length thereof for more detailed information. Forexample, the internal EPR measurements (i.e., the EPR measurements madeby the mobile EPR device 1601) may be utilized to more accurately locateareas of interest between external immobile EPR sensors (e.g., EPRsystems 200 in FIG. 15) deployed along the same and/or a differentlength of the conduit. For certain aspects, the mobile EPR device 1601may monitor changes in the fluid along the conduit. For example, ifthere was an interval along the conduit with a significant generation ofcorrosion ions or a dropout of asphaltene, the EPR sensor of the mobileEPR device 1601 may be able to more accurately locate the specificsource of the change than an immobile EPR sensor.

Any of various species in the fluid may be measured by a mobile EPRdevice 1601. For example, the species being sensed may include freeradical and transition metal ions, such as asphaltene (free radicals),scales, iron oxides, iron carbonates, iron sulfides, and tracers thathave an EPR signature.

A mobile EPR device 1601 may provide or allow for a spectroscopic viewof the paramagnetic components of the sample, and may also haveadditional sensors thereon. For example, a mobile EPR device 1601 mayderive permittivity, conductivity, density, viscosity, pressure, and/ortemperature of the fluid in the conduit. In the case of permittivity, anEPR sensor of a mobile EPR device 1601 may derive—or transmitinformation for derivation of—a spectrum of complex permittivity valuesover a frequency range.

By employing a mobile EPR device 1601 in this manner, EPR measurementsmay be taken along a length of a conduit while a multiphase fluid isflowing. In addition, properties of an individual phase of themultiphase fluid may be extracted, and/or inferences of the flow andprecipitation along the conduit may be made. This information may beused to manage a flow assurance program. As another example, theoperations 800 of FIG. 8 may be performed utilizing a mobile EPR device1601 deployed in the pipeline 220.

For certain aspects, the fluid flowing in the conduit may both: (1)convey the mobile EPR device 1601 through the conduit and (2) passthrough the EPR sensor of the mobile EPR device 1601. In this case, themobile EPR device 1601 may include a valve mechanism that opens to allowfluid flow through the EPR sensor of the mobile EPR device 1601.Additionally or alternatively, the mobile EPR device 1601 may beconfigured with a pressure drop along a flow-through, such that themobile EPR device 1601 may be propelled while concurrently allowingfluid to flow through the EPR sensor of the mobile device.

The mobile EPR device 1601 may begin at the first section 1607 ofconduit and traverse at least a portion of the conduit due to the fluidflowing in the conduit. While the mobile EPR device 1601 traverses thefirst section 1607 of conduit to reach the second section 1608, themobile EPR device 1601 may perform EPR sensing of the fluid. Themeasurements may be made while the mobile EPR device 1601 is stationaryor while the mobile device is moving. The movement of the mobile EPRdevice 1601 may be tracked by the ROV 1610. The ROV 1610 may detect alocation of the mobile EPR device 1601 and may, in addition, communicateinstructions to the mobile EPR device 1601 and/or receive data from themobile EPR device 1601. Instructions communicated to the mobile EPRdevice 1601 may include instructions to activate a flow control valve,for example.

FIG. 17A is a cross-sectional diagram of an example mobile EPR device1700, in accordance with certain aspects of the present disclosure. Theexample mobile EPR device 1700 of FIG. 17A includes a housing 1706, oneor more EPR sensors (e.g., EPR systems 200), a distance-measuring device1702, a bore 1704 in the housing, and a pump 1701. The bore 1704 mayhave a tapered shape (e.g., a frustoconical bore) to enable the EPRsensor(s) to measure fluid that enters the mobile EPR device 1700 fromupstream, while also causing the flowing fluid to impart momentum to themobile EPR device 1700. As has been noted, it may be advantageous tomeasure properties of fluid that is downstream of the mobile EPR device,whereas the positive pressure difference from point 1605 to point 1606downstream (see FIG. 16, described above) will cause the fluid to flowfrom upstream to downstream. In this scenario, it can be advantageous toinclude in the mobile EPR device 1700 a pump 1701 that can cause flow ofdownstream particles to move upstream into the mobile EPR device.Causing the flow of downstream particles to move upstream into themobile EPR device 1700 brings those particles into proximity with one ormore of the EPR sensors, enabling the EPR sensors to measure theparticles and fluid from downstream of the mobile EPR device. Thedistance-measuring device 1702 may be used to monitor distance frommobile EPR device 1700 launch and may also be used to confirm that themobile EPR device was stationary during one or more measurements. Themobile EPR device 1700 may include an anchoring mechanism (not shown) tohelp ensure the mobile EPR device is immobile during a measurement, ifdesired. As depicted in FIG. 17A, each EPR sensor is a separateassembly, but for other aspects, there may be some shared componentsbetween the EPR sensors. For example, the EPR sensors may use the samehigh power programmable current source 202, power module 204, controllermodule 206, and/or transceiver module 208, but have separate resonatorassemblies 210 (see FIG. 2).

FIG. 17B shows a cross-sectional view of an example mobile EPR device1751 having a bore 1704 and a valve 1703, in accordance with certainaspects of the present disclosure. Mobile EPR device 1751 is similar tomobile EPR device 1700, illustrated in FIG. 17A, with many of the sameor similar components. Therefore, only components of mobile EPR device1751 that may differ from the components of mobile EPR device 1700 aredescribed. By adding a valve 1703, it is possible for mobile EPR device1751 to accomplish, with only a single EPR sensor (e.g., EPR system200), EPR sensing operations similar to those that mobile EPR device1700 can accomplish. With the valve 1703 in a first position, fluid fromupstream of the mobile EPR device 1751 will flow into the EPR sensor,enabling measurement of the fluid from upstream of the mobile EPR device1751 by the EPR sensor. With the valve 1703 in a second position, thefluid from downstream of the mobile EPR device 1751 will be pumped bythe pump 1701 through the EPR sensor, enabling measurement of the fluidfrom downstream of the mobile EPR device 1751 by the EPR sensor.

FIG. 18 is a flow diagram of example operations 1800 for sensing a fluidflowing in a conduit, in accordance with certain aspects of the presentdisclosure. The operations 1800 may be performed by a mobile EPR device(e.g., mobile EPR device 1601 shown in FIG. 16, mobile EPR device 1700depicted in FIG. 17A, or mobile EPR device 1751 shown in FIG. 17B) asdescribed herein.

The operations 1800 may begin at block 1802 by traversing a section ofthe conduit with the mobile EPR device due to the flowing fluid. Forexample, mobile EPR device 1601 (see FIG. 16) traverses a section ofpipeline 220 from a first section 1607 of conduit to a second section1608 of conduit.

At block 1804, operations 1800 continue with the mobile EPR deviceperforming EPR sensing of the fluid while the mobile EPR devicetraverses the section of the conduit. Continuing the example from above,one or more EPR sensors (e.g., EPR systems 200) in mobile EPR device1601 perform EPR sensing of the fluid while the mobile EPR device 1601traverses the section(s) of the pipeline 220.

Any of the operations described above, such as the operations 500, 600,700, 800, 900, 1000, 1300, and/or 1800 may be included as instructionsin a computer-readable medium for execution by a control unit (e.g.,controller module 206) or any other processing system. Thecomputer-readable medium may comprise any suitable memory for storinginstructions, such as read-only memory (ROM), random access memory(RAM), flash memory, an electrically erasable programmable ROM (EEPROM),a compact disc ROM (CD-ROM), a floppy disk, and the like.

While the foregoing is directed to certain aspects of the presentdisclosure, other and further aspects may be devised without departingfrom the basic scope thereof, and the scope thereof is determined by theclaims that follow.

The invention claimed is:
 1. A mobile electron paramagnetic resonance(EPR) device for deploying in a conduit, the mobile EPR devicecomprising: a housing configured to be conveyed by a fluid flowing inthe conduit; a bore in the housing for receiving the fluid; and an EPRsensor disposed adjacent to the bore for EPR sensing of the fluid as themobile EPR device traverses a section of the conduit.
 2. The mobile EPRdevice of claim 1, further comprising at least one other sensor forextracting at least one characteristic of the fluid.
 3. The mobile EPRdevice of claim 2, wherein the fluid comprises a multiphase fluid andwherein the at least one other sensor is configured to extract at leastone characteristic of at least one of a first phase or a second phase inthe multiphase fluid.
 4. The mobile EPR device of claim 3, wherein theconduit comprises a pipeline for hydrocarbon recovery operations,wherein the first phase comprises an oil component of the multiphasefluid, and wherein the second phase comprises a water component or a gascomponent of the multiphase fluid.
 5. The mobile EPR device of claim 3,wherein the at least one characteristic comprises at least one of avolume fraction of the first phase or a volume fraction of the secondphase.
 6. The mobile EPR device of claim 1, further comprising a valvemechanism disposed in the bore and configured to open to allow the fluidto flow through the EPR sensor.
 7. The mobile EPR device of claim 1,wherein the bore is shaped to provide a pressure drop in the fluid.
 8. Amethod of sensing a fluid flowing in a conduit using a mobile electronparamagnetic resonance (EPR) device, comprising: traversing a section ofthe conduit with the mobile EPR device due to the flowing fluid; andperforming EPR sensing of the fluid while the mobile EPR devicetraverses the section of the conduit.
 9. The method of claim 8, furthercomprising extracting at least one characteristic of the fluid using themobile EPR device.
 10. The method of claim 9, further comprisingdetermining at least one property of the fluid based on the EPR sensingand the at least one characteristic.
 11. The method of claim 10, whereinthe fluid comprises a multiphase fluid and wherein the extractingcomprises extracting the at least one characteristic of at least one ofa first phase or a second phase in the multiphase fluid.
 12. The methodof claim 11, wherein the conduit comprises a pipeline for hydrocarbonrecovery operations.
 13. The method of claim 12, wherein the mobile EPRdevice comprises a pipeline pig with an EPR sensor.
 14. The method ofclaim 12, wherein the first phase comprises an oil component of themultiphase fluid and wherein the second phase comprises a watercomponent or a gas component of the multiphase fluid.
 15. The method ofclaim 14, wherein the at least one characteristic of the fluid comprisesa volume fraction of the oil component and wherein the at least oneproperty of the fluid comprises a concentration of asphaltene in the oilcomponent.
 16. The method of claim 10, further comprising determining atleast one electromagnetic attribute of at least a portion of the fluid,wherein determining the at least one property of the fluid comprisesdetermining the at least one property of the fluid based on the EPRsensing, the at least one characteristic, and the at least oneelectromagnetic attribute.
 17. The method of claim 16, whereindetermining the at least one electromagnetic attribute is based onperforming the EPR sensing and wherein the at least one electromagneticattribute comprises at least one of a conductivity, a dielectricproperty, a magnetic susceptibility, or a magnetic permeability, of theat least the portion of the fluid.
 18. The method of claim 10, whereinthe determining comprises determining changes in the at least oneproperty of the fluid as the mobile EPR device traverses the section ofthe conduit.
 19. The method of claim 10, wherein the at least oneproperty comprises a concentration of asphaltene in the fluid.
 20. Themethod of claim 8, further comprising controlling a valve to allow atleast a portion of the fluid to enter a resonator of an EPR sensor inthe mobile EPR device before performing the EPR sensing.